Current mechanical, electromagnetic or optical sensor technologies are relatively low-tech and passive, and do not acquire data at sufficient distances to permit reservoir managers to fully comprehend the chemical composition, volume and dynamics of the petroleum in a given reservoir. The most advanced tool for monitoring the wells is a multiphase flow meter. It monitors the flow rate of oil, water and gas. There is no tool or methodology that can provide the information about the quality of the oil such as hydrocarbon content and the oil to water ratio, which related to the volume and production enhancement methods (i.e. steam injection).
In large part, the future of the oil and gas industry depends on the ability to better understand the volume and dynamics of a reservoir to optimize production and avoid damaging the reservoir or interrupting flow through over-production or other production enhancement methods such as steam injection. The disclosed chemical nanosensor network, combined with the physical (micro)sensors such as humidity, temperature and pressure, acoustic or electromagnetic wave, form a monitoring system can substantially improve the quality and production of the oil by monitoring the chemical composition in wells and then feed back the information to the decision maker to modify and fine tune the production enhancement methods in real time to improve the oil quality and control the quantity. Without adequate and reasonably complete data for a candidate wellsite, the success rate is presently 20-25 percent and has not increased much in the last 20 years.
The geographic market for this technology is global. Large and small U.S. and North American reservoirs are applicable, so as those worldwide reservoirs. The potential of this new technology to dramatically increase oil production will have a significant downward impact on world prices. Even a marginal enhancement of the sensor capability of oil and gas monitoring will produce exponential benefits. The potential of heavy oil is entirely technology driven. In situ production methods (as opposed to open pit mining methods) require steam injection that causes the liquefaction of tar sands deposits. But without solid data regarding the dynamics of the geological system, production techniques result in only a 20-25% recovery rate. The future ability of conventional oil and gas production to meet world energy demand while also reducing political tensions depends almost entirely on increasing the productivity of known reserves through new technology significantly upward from the current average of approximately 33%. There currently is no active monitoring system on the market capable of meeting that requirement.
What is needed is an integrated system and method for estimating one or more qualitative or quantitative parameters associated with an underground reservoir of a fluid mineral (e.g., oil or natural gas) that permits a more accurate assessment of the economic potential of the reservoir. Preferably, this assessment should include one or more of local (underground) values relative humidity, temperature, gas pressure, fluid level, and/or presence/absence of one or more target molecules, such as CmHn. Preferably, this assessment should also permit an estimate of direction and flow rate (represented by a current vector J) of the fluid in response to pressurization or other perturbation of the fluid mineral resource. Preferably, this approach should apply to evaluation of a “new” well (identified but not yet developed), of a producing well and of a capped well.